Ben Boettger

KENAI — Crude oil from Cook Inlet’s west side will now reach Marathon’s refinery in Nikiski by pipeline instead of tanker after Hilcorp completed the $90-million project.
Eliminating cross-inlet tanker traffic also eliminates the need for the Drift River oil terminal, realizing a long-sought goal of conservationists and oil-spill prevention specialists.
During a ribbon cutting in Kenai on Oct. 19 for the Cross-Inlet Pipeline Project, operations manager Rich Novcaski of Hilcorp’s pipeline-owning subsidiary Harvest Alaska said the first oil was piped across the Inlet the night before, traveling through an underwater line, which previously carried natural gas.
The displaced gas will travel through another pipeline that historically carried gas produced from the Tyonek Platform to the now inactive LNG export terminal on the Inlet’s east side.
To complete the cross-inlet connection, Hilcorp laid about six miles of new pipe from the Tyonek Platform to the existing west-side pipeline network. At the ribbon cutting Novcaski said gas would start flowing through that connection the following day.
“What I think this project ultimately embodies is a very creative use of all the infrastructure — gas lines, oil lines, and a limited amount of new construction for something very cost-effective,” said Hilcorp’s Sean Kolassa, president of Hilcorp’s Harvest Midstream pipeline subsidiary.
In a previous public presentation, Novcaski said tankering oil across the inlet cost about $3 per barrel while piping it cost about $2 per barrel, and estimated the cross-inlet pipeline could extend the economic life of Cook Inlet oil production by about 20 years.
Drift River’s outflow into Cook Inlet is among the few places where the west-side coast has depth to accommodate tankers, but as a location for a crude oil terminal, it has a downside, too; the Drift River tank farm is about 20 miles from the volcanic Mount Redoubt and has been threatened twice by its eruptions.
The ribbon was cut by Mike Munger, a long-time advocate for decommissioning the terminal. When Redoubt’s eruptions from December 1989 to January 1990 sent floods and mud flows toward the tank farm, Munger was an environmental specialist at the Alaska Department of Environmental Conservation and helped oversee installation of new defenses at Drift River: two diversionary dikes in the Drift River valley and a 20-foot wall of concrete-armored earth surrounding the tank farm.
By the time floods from a second eruption prompted Drift River to be shut-in in 2009, Munger was executive director of the oil spill prevention group Cook Inlet Regional Citizens Advisory Committee. In 2012, CIRCAC passed a resolution calling for Drift River to be replaced with a subsea pipeline within five years.
“So they’re a little behind, but not by much,” Munger said. “But it’s really a milestone for our organization to see this come to fruition.”
He noted in an interview with the Journal that closing the tank farm during the last eruption also meant halting west-inlet oil production as there was simply no place to put the crude.
“This will allow them during a volcanic eruption, in theory anyway, to continue oil production unless of course the offshore platforms were somehow threatened,” Munger added.
CIRCAC received the U.S. Coast Guard’s Meritorious Public Service Award during the council’s Sept. 7 board meeting in Kodiak. Alaska Coast Guard officials cited the council’s leadership on maritime safety and environmental stewardship in the region, according to a council release.
It marks the second time CIRCAC has received the award; the first being in 2010 for its work during the last Redoubt eruption.
Novcaski said the project involved 57 contractors, 27 of whom did on-site work. The heaviest construction was on the six-mile connection to the Tyonek Platform. The pipe was assembled in mile-long segments on shore and pulled into the Inlet by barge, making it the longest pull barge construction in Cook Inlet.
For its distance, this method was about half the cost of using a lay barge, though Cook Inlet, with its strong tides, “is not an easy place to do business,” he said.
Cataloging other Cook Inlet oil lines
The commissioning of the cross-inlet oil transmission line coincides with the start of a study analyzing the state of the rest of Cook Inlet’s oil lines, another long-time priority of CIRCAC.
The Cook Inlet oil pipeline risk assessment will ultimately be a one-stop shop for all of the available information on each Cook Inlet pipeline used for oil production, according to Munger. It will focus not only on oil transmission lines but also pipelines that carry water produced alongside oil and gas lines used to support oil production, such as those that carry fuel gas to oil platforms, he clarified.
“The fact remains, a big bulk of this infrastructure has been in place since the mid- to late ‘60s in one of the most inhospitable bodies of water in North America (where) it is virtually impossible to do any visual inspection on it,” Munger said in highlighting the need for the first-time review.
“It’s long overdue but we’ve been advocating for it since at least 1999, I believe. Like many things it takes a long time to get things going.”
Hilcorp’s drawn out subsea natural gas pipeline leak during the winter of 2017 underscored the challenges of dealing with a wintertime spill in Cook Inlet and regenerated a discussion about the need to know more about the underwater pipeline network in Alaska’s original oil basin.
The Hilcorp leak demonstrated that if there was a large spill in the Inlet in winter there is little else that can be done other than shutting off the source, Munger said, as strong tidal currents and drifting ice pans would make recovering oil nearly impossible.
“That circles back to prevention is the key; that’s the mantra by which we live by. You have to keep the oil in the pipe; you have to keep the oil in the tanker and you need to put money towards that to make sure that happens,” he said.
The money for the pipeline assessment so far has come through a $50,000 allocation from CIRCAC itself, a $200,000 appropriation from the Legislature through the state Department of Environmental Conservation and a grant from the Kenai Peninsula Borough.
CIRCAC leadership also recently approved an additional $31,000 for the project and the council is waiting to hear about a potential grant from the federal Pipeline and Hazardous Materials Safety Administration, or PHMSA, according to Munger.
He said the council has sufficient funds to complete the work now and the added federal money would only enhance the review.
At its most basic level, the assessment should help clarify which state or federal agency has jurisdictional authority over some of the oil lines in the inlet, Munger added.
Tim Robertson, a principal with the consulting firm Nuka Research and Planning Group of Seldovia, which CIRCAC hired to conduct the assessment, said the final report will be a snapshot of inlet oil production lines taken in early 2019.
The information will be gathered from all available public sources as well as from the operators; Nuka will not be gathering original data, according to Robertson.
“We’ll break it down into individual pipelines and then develop a database of information about each individual pipeline. It’s everything from its ownership and history to who installed it and how it was installed to its physical specifications; what kind of corrosion and other prevention measures (are) in place for that pipeline; any spill history that pipeline has had; any repairs that have been done to that pipeline,” Robertson explained.
That information will feed a database that will generate a report and that report will be forwarded to industry experts who will then discuss it with the operating companies, regulators and the public, culminating in a final set of recommendations on how to best manage the pipelines in the coming decades, he said.
The data gathering should be done by March, with the experts convening in May. Robertson said the assessment is currently scheduled for completion in the first quarter of 2020, but the schedule is tentative given the multiple inherent logistical challenges involved.
“We all have a common interest. There’s nothing to really disagree about here,” he said. “It’s basically, what are the recommendations of some of the best minds in the industry about how to keep this going and producing into the future.”
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Journal reporter Elwood Brehmer contributed to this story.

Hilcorp’s Anna Platform has resumed work after having been shut down since a suspected oil release April 1. An Alaska Department of Environmental Conservation (DEC) situation report released Saturday states that the platform’s crude oil pipeline to onshore facilities — the suspected source of sheens seen on the surface of Cook Inlet on which prompted the shutdown — was restarted May 2, watched by observers from DEC, U.S. Coast Guard, and the federal Pipeline and Hazardous Materials Safety Administration (PHMSA), who saw no oil releases.
The material spilled April 1 wasn’t crude oil as originally suspected, according to the DEC report, but natural gas condensate — hydrocarbons found in natural gas that become liquid at surface temperatures — and it came not from the oil pipeline but from the platform’s flaring system, used to burn off excess natural gas pumped up along with oil. The release “resulted from an upset condition” in the flare system, according to the situation report.
Hilcorp had previously calculated that three gallons of material were released in the April 1 incident. The DEC report states that this was based on the subsequent discovery of five gallons of liquid in the maximum eight-gallon condensate pipeline.

Last weekend contracted dive crews from Homer visited Hilcorp’s underwater fuel gas pipeline and located the source of the rupture believed to have been leaking methane since late December. The danger presented by Cook Inlet’s iced-over surface had previously prevented divers from reaching the pipe.
According to a Monday announcement by Hilcorp, the leak — which initially released between 225,000 and 325,000 cubic feet of methane per day into the Inlet, but was greatly reduced after Hilcorp shut down the two oil platforms powered by the piped gas on March 25 — comes from a two-inch opening on the bottom of the pipeline, which divers found resting on a seafloor boulder.
The eight-inch diameter pipeline , built by Shell Oil Company in 1964, has leaked at least twice before in similar circumstances. Federal regulators of the Pipeline and Hazardous Materials Safety Administration cited leaks in August and June 2014, when the pipeline was owned by XTO Energy. According to PHMSA’s March 3 safety notice to Hilcorp, those leaks “were caused by rocks contacting the pipeline in areas where the pipeline was not continuously supported by the seabed.”
“The rocks contacting the pipeline deteriorated the steel pipe wall by abrasion, resulting from relative movement between the pipeline and rocks contacting the pipeline,” the PHMSA notice states. Both previous leaks were approximately two-thirds of a mile from the present leak and 42 yards apart from one another.
According to the Hilcorp announcement, divers are preparing the site for the installation of a temporary clamp around the pipeline. The pipeline has been leaking between 88,000-110,000 cubic feet of methane per day since Hilcorp’s March 25 decision to reduce the pipeline pressure to the minimum necessary to prevent it from flooding and to power the platforms’ safety equipment.
“Following completion of the initial repair, further inspection and work will be done to permanently repair the affected segment of pipe,” Hilcorp’s announcement reads. “The line will not be returned to service until permanent repairs have been completed, the line has been pressure tested, and regulators have approved a re-start.”
Anna Platform pipeline pressure-tested
Hilcorp’s Anna Platform, which was shut down April 1 after its crew felt an impact and saw bubbles from around one of legs, is still being investigated as a possible source of oil sheens that Hilcorp helicopters spotted in the Inlet later that day, the largest 10 feet by 12 feet.
The crude oil pipeline that carries Anna Platform’s production to the nearby Bruce Platform, from which a separate pipeline carries it to the onshore Granite Point tank farm, was the suspected source of the sheen. After the pipeline was cleaned and flooded the next day, a response team with officials from Hilcorp, Alaska Department of Environmental Conservation (DEC), and the U.S Coast Guard disbanded.
On Monday the Anna Platform’s pipeline underwent a pressure test that DEC spokesperson Candice Bressler wrote effectively ruled out the pipeline as the source of the oil discharge. According to a Hilcorp announcement, the eight-hour test put the pipeline at 125 percent of its maximum operating pressure, with the result that “the pipeline held pressure throughout the test, meaning the pipeline is in good working order.”
Other sources of the oil discharge — which DEC estimated at a maximum of 10 gallons, and Hilcorp estimated at less than three gallons, based on the size of the sheens observed and the amount of oil recovered from the pipeline — are still being investigated. DEC has required Hilcorp to submit a repair plan once the source is discovered.
The two leaks — as well Hilcorp’s emptying on April 3 of a suspected third leaking gasline from its Steelhead Platform — have prompted environmentalist groups to call for an inspection of Cook Inlet’s pipeline and platform infrastructure, much of which has survived from the 1960s amid the Inlet’s strong, scouring tidal currents. The Arizona-based Center for Biolgoical Diversity has petitioned PHMSA and DEC for such an inspection, as has Cook Inletkeeper in a letter to Alaska Governor Bill Walker.
Reach Ben Boettger at [email protected]

Hilcorp announced plans on Saturday to halve the pressure in its leaking Cook Inlet natural gas pipeline, requiring the halt of oil production from two Cook Inlet platforms powered by fuel gas pumped through the ruptured pipe.
Communications Director Grace Jang of the Office of the Governor said that Gov. Bill Walker had reached out to Hilcorp CEO and founder Jeffery Hildebrand and in the past couple of weeks had held phone conversations with him, as well as meetings with Hilcorp Alaska executives and officials of the Alaska Department of Environmental Conservation, who are regulating the leak’s environmental impacts.
“The governor was very concerned about the length of time it had been leaking, and about potential irreversible effects, and he wanted to make sure that there was a plan of action going forward,” Jang said.
A Saturday press release from Walker’s office stated that he and the Hilcorp executives “agreed the best course of action at this time is to enact a temporary shutdown of the company’s oil and gas production in order to reduce safety risks and environmental impact.”
Hilcorp first announced the leak— from a pipeline supplying fuel gas to four oil platforms built in 1964 in the Middle Ground Shoal oilfield, about five miles from the coast of Nikiski — on Feb. 7 after confirming it with a helicopter observation. Hilcorp had begun investigating a pressure drop in the pipeline in January, and subsequent analysis suggests the leak started in late December 2016. Hilcorp has delayed plans for divers to repair the pipeline because of ice that continues to cover the Inlet’s surface, which could compromise the divers' safety.
Since the leak’s discovery, the two active Middle Ground Shoal platforms — Platforms A and C — have continued to produce crude oil, which they’ve pumped to shore via a pipeline paralleling the fuel gas line.
Hilcorp originally disclosed a leak rate of between 225,000 to 325,000 cubic feet of methane per day to the Alaska Department of Environmental Conservation. By Feb. 16, Hilcorp had lowered the leak estimate to 210,000-310,000 cubic feet per day, by “shutting off non-essential equipment on the platforms,” according to a Hilcorp statement of that date.
The reduction had required reducing the pipeline pressure three times since the start of the leak — from its normal 195 pounds per square inch to 165 pounds per square inch, according to a Feb. 20 letter from Hilcorp Alaska Vice President David Wilkins to the DEC. To do so, the platforms shut down operations such as pumping seawater to pressurize oil wells.
With 145 pounds per square inch of gas pressure presently in the pipeline, the leak rate estimate is now between 193,000 to 215,000 cubic feet per day, according to DEC’s incident webpage.
The pressure drop announced Saturday will take the pipeline to about 65 pounds per square inch — according to a Hilcorp statement, the minimum required to prevent the gasline from flooding and to continue powering heaters and platform safety equipment that will prevent other oil lines from freezing or breaking.
A Hilcorp statement on Saturday cited weather as a reason for not previously attempting the pressure and power reductions.
“Shutting in wells and idling lines and equipment in very cold temperatures create a known risk of freeze-up and potential rupture,” the release states. “Warmer ambient temperatures now permit a safer shut in process of the wells along with the associated lines and equipment.”
Prior to 2005, the fuel gas line carried produced crude from the platforms. Hilcorp has previously stated that residual crude in the gasline could escape into the Inlet if the gas line floods, and that the parallel crude pipe could also freeze and rupture if its contents — about 65 percent water, according to federal regulators of the Pipeline and Hazardous Materials Safety Administration — are unheated.
Hilcorp plans to shut in the platforms this weekend, and based on weather forecasts, “anticipates repair operations to occur in the next two weeks,” according to the statement.
Hilcorp spokesperson Lori Nelson wrote that the two platforms are together producing about 1,600 barrells of crude oil per day, which are piped to the Tesoro petroleum refinery in Nikiski. Tesoro spokesperson Kate Blair said the refinery is able to make up for the lost supply from other sources.
A press release from Walker’s office states “Hilcorp executives committed to Governor Walker that they will not be starting up production at the platforms again until federal and state regulators are satisfied the oil and gas lines can be operated safely and in accordance with all applicable laws.”
Nelson said no platform employees would be laid off during the shutdown.
The pressure drop is expected to bring the leak rate to 88,000 - 110,000 cubic feet of methane per day, according to an email from DEC's Spill Response and Prevention Director Kristin Ryan.
The behavior and the effects of the methane already released into the Inlet are still matters of investigation. On Wednesday Hilcorp submitted to DEC its first measurements of water quality at the leak site, made by sensors suspended at three different depths from a buoy that floated above the methane release point.
Hilcorp’s Wednesday report — the first of the weekly monitoring reports it will submit to DEC — details measurements from four trips the sensor buoy made through the leak area on March 18 and March 19, when it measured three water properties — dissolved methane, dissolved oxygen and dissolved carbon dioxide.
While much of the leaked methane may bubble into the atmosphere, enough of it might dissolve in the water to create a deoxygenated state known as hypoxia, in which fish can asphyxiate. Hypoxia exists in water with less than 2 - 3 milligrams of oxygen per liter of water, according to the Ecological Society of America.
The lowest dissolved oxygen reading obtained in the first four runs of Hilcorp’s sensor buoy was 7.8 milligrams of oxygen per liter of water. The buoy found this reading in an area 41 feet deep and approximately 492 feet long, in which the dissolved oxygen measured about 27 percent lower that of the surrounding water,which had 9.3 milligrams of oxygen per liter of water.
Methane toxicity is another concern. In a Feb. 10 letter to Hilcorp, DEC’s On Site Coordinator Geoff Merrell wrote that the gas can be lethal to fish if dissolved in concentrations greater than 1 milligram of methane per liter of water.
Hilcorp has previously predicted the level of dissolved methane at the leak would be one-five hundredth of that lethal amount, citing a computer model it commissioned, which concluded that 84 percent of the leaked methane is likely to reach the atmosphere, while 17 percent will dissolve in the water.
The buoy’s highest detected methane concentration — .15 milligrams per liter — was less than the lethal 1 milligram per liter, but three times higher than the model-predicted .05 milligrams per liter.
DEC Program Manager Graham Wood wrote in a March 23 letter to Hilcorp Environmental Manager William Britt that this methane level is also “above concentrations shown to cause adverse responses to fish” — between .02 and .05 milligrams per liter, according to Wood.
In natural and artificial methane underwater releases, gas dissolved in the water is eventually digested by aquatic microbes. Chemical oceanographer Sue Saupe, Director of Science and Research for the Cook Inlet Regional Citizen’s Advisory Council, said there hasn’t been much previous research about the methane-digesting microbes of Cook Inlet — where they exist and in what quantity. According to Saupe, uncertainties still exist about the state of released methane in the Inlet, and about how Saturday’s pressure reduction could affect its eventual dispersion and decomposition.
“Without more information on the true extent and shape of the plume, it’s hard to say how extensive the decreased (dissolved oxygen) levels and increased methane concentrations are,” Saupe wrote in an email. “By halving the flow rate into the pipeline, the flux of gas into the Inlet will decrease but may not have an exactly linear effect on methane and dissolved oxygen concentrations immediately, depending on activity, location, and efficiency of (methane-digesting microbes).”
Update:
During the weekend, Hilcorp finished shutting in the Middle Ground Shoal Platforms A and C during the weekend, according to a Monday statement from Hilcorp spokesperson Lori Nelson. With the adjacent crude pipeline no longer carrying oil, Nelson wrote that filtered seawater is being circulated through it to reduce its risk of freezing. Hilcorp expects to begin sending divers to repair the gas pipeline in the next 10 days, Nelson wrote.
Reach Ben Boettger at [email protected]

Hilcorp’s plan to send divers to repair a damaged underwater natural gas pipeline — which is leaking between 210,000 and 310,000 cubic feet of methane a day into Cook Inlet — isn’t likely to happen until mid-to-late March, according to a Feb. 20 letter from Hilcorp Alaska Senior Vice President David Wilkins to the Alaska Department of Environmental Conservation’s Geoff Merrell, the on-scene coordinator for the leak.
The damaged pipeline was built in 1964 and until 2005 was used to carry crude oil produced at the platforms to shore. It now carries processed natural gas — approximately 98 percent methane — to Hilcorp’s Platform A, which burns the gas as fuel and distributes it to three other Hilcorp platforms in the area — known as the Middle Ground Shoal — which are also powered by it.
Surface disturbances from the leak were spotted by a Hilcorp helicopter on Feb. 7 and reported to DEC that day. After ice covered the area, the disturbance was no longer visible. The ice has also inhibited Hilcorp’s plans to investigate and treat the leak with a team of divers, resulting in the expected delay.
DEC Coordinator Merrell first wrote to Wilkins regarding the leak in a Feb. 10 letter that requests five pieces of information from Hilcorp, including what alternatives the company has to the initial plan of responding with a dive team, and what plans Hilcorp has to monitor “potential impacts to resident or returning salmonid species, reproducing halibut populations, potential impacts to endangered species, and key prey species relied upon by these species.”
In his response, Wilkins summarized Hilcorp’s response actions up to that time: reducing platform activities to decrease the need for fuel gas, and dropping the pipeline flow to roughly 84 percent of its normal pressure. One shut-down operation, Wikins wrote, is the pumping of seawater to pressurize the Middle Ground Shoal’s oil-bearing rock. This water flood operation has been shut down on two of the four platforms — A and C — in the Middle Ground Shoal. Wilkins wrote that “over the course of time, the water flood shut down will impact the rate of oil production and may reduce the recoverable reserves from the field.”
As for alternatives to the dive plan, Wilkins wrote of three other repair options, all of which he stated would be less viable than repair by divers. Remote-operated underwater vehicles (ROV) aren’t available to Hilcorp, Wilkins wrote, adding that the silted water of Cook Inlet could blind ROV cameras. Repairing the pipe by pushing extra tubing into it is impractical because the leak is the beyond the maximum reach to which tubing could be pushed, nor does technology exist to repair the leak from the surface without divers, he wrote.
Simply shutting down the pipeline and the platforms it powers could create worse problems, according to Hilcorp. The pipeline contains residual crude oil that could leak into the Inlet unless pressure is maintained in the pipe. With the platforms turned off, the parallel pipeline that presently brings crude oil to shore may freeze (due to the water content of crude oil) where it leaves the water, leading to an oil spill when it thaws in the spring, Wilkins wrote.
Because of these possible complications, Wilkins wrote that “it is not simply a matter of whether the methane leak continues until the Pipeline can be repaired.”
“Rather, the choice is between the current methane release … and one or more oil spills, along with other potential damage and additional risks,” Wilkins wrote.
Merrell will be responsible for evaluating the adequacy of Hilcorp’s response plans, according to Merrell’s letter to Wilkins.
“If your response actions are not satisfactory, (DEC) may assume the lead role in the investigation and cleanup efforts,” Merrell wrote to Wilkins, adding that Hilcorp may be held responsible for the cost of the state’s actions in this case. Hilcorp will also be responsible for the cost of the state’s oversight activities, Merrell wrote.
The possible environmental effects of the methane release remain uncertain. Wilkins cited Hilcorp-commissioned work by environmental consultant group SLR International, which estimated with a computer model that 17 percent of the methane is likely to be dissolved in the water, while 83 percent would reach the atmosphere, resulting in a water-methane concentration that Hilcorp’s study concluded would be 1/500th of the minimum methane concentration stated to be harmful to marine life in DEC’s letter.
In a Feb. 24 letter to Chris Hoidal, director of the federal Pipeline Hazardous Materials Safety Administration regarding effects of the leak on harbor seals, belugas, porpoises, and other marine mammals, National Marine Fisheries Service Administrator James Balsiger wrote that “modeling efforts alone are not sufficient to reach a conclusion regarding potential effects to marine mammals” and recommended air and water sampling to determine effects. As of the letter’s date, no air or water samples had been made to determine methane concentrations at the site, Balsiger wrote. He cited other models that had shown potential for a zone of low-oxygen water surrounding the leak.
“Modeling suggests a relatively localized zone of low-oxygen, high-methane concentrations, but this has not been validated with incident-specific samples,” Balsiger wrote.
Reach Ben Boettger at [email protected]

Back in April, when Roger Boyd was getting Red Run Cannabis Company licensed by the Kenai city government, he told the city Planning and Zoning commission he considered it a statement as much a business. He now considers his statement made.
At Red Run’s opening at noon on Monday, a line stretched to the end of the business’s parking lot. By 1:30, the line remained about the same in length.
Although licensed as both a marijuana cultivator and retail store, the excitement at Red Run Monday was on the retail side.
For customer Carol Schuldt — shopping with her friend Marti Butcher, who had come down from Anchorage for the occasion — Red Run represented a big difference from “the days when you had to buy it from your aunt’s cousin’s brother, or somebody.”
“I can choose what I want, like buying a fine wine, and I can stop by and get it on my way to Home Depot,” she said.
She saw at least one other advantage to the shop.
“I’m not a criminal!” Schuldt shouted as she left the store, which is located in a renovated One Stop gas station and convenience store owned by Boyd. She carried her purchase in an opaque bag.
The line outside the door cheered.
Strains and suppliers
Red Run co-founder Eric Derleth showed off Red Run’s three cultivation rooms and outlined the technical complexities needed to not only grow the plants — the building’s air circulates through two HVAC systems — but also to secure them. Red Run has 30 security cameras feeding footage into about 40 terrabytes of storage, backed up in a secure cloud service.
Derleth expects Red Run’s own marijuana to be saleable in January. He said that suppliers presently control the marijuana market, and they're struggling to keep up.
“It’s a matter of having relationships with people and tapping into that,” he said.
Relationships between marijuana activists have made the Alaska marijuana industry possible, Derleth added, even though in many cases these activists are now business competitors.
Derleth and Red Run co-founder Marc Theiler are founding members of the Kenai Community Coalition on Cannabis, and their relationship with fellow advocate Leif Abel allowed Red Run to have its opening: the product it offered Monday was grown outdoors this summer by Abel's Kasilof-based cultivator, Greatland Ganja.
“Greatland Ganja had nine strains, and we worked that out with them ahead of time because they were selling it so fast,” Derleth said. “They held on to it as a good faith gesture.”
Red Run sold all nine strains at the same price: $20 per gram, which some customers said is comparable to, or just slightly above, the street price. Derleth said some black market marijuana can go for $10 a gram, a price he hopes Red Run will be able to reach in two years as more cultivators come into the market.
Missing from Red Run’s sales counter on Monday were marijuana oils, concentrates, and edibles. Alaska has only three licensed marijuana product-manufacturing facilities, and Derleth said the slim supply has kept their productivity low. Red Run plans to sell such products in the future.
At the opening, Abel stood behind a counter with sample buds from each of his strains in jars with vents for smelling. He said that between the weather, technical hang-ups, and his company’s licensing process, completing an outdoor harvest this summer hadn’t been certain. Nonetheless, he said the product sold Monday had been harvested two months ago. It had been delayed by state-required product testing. Currently only two labs are licensed for marijuana testing: one in Anchorage and one in Fairbanks.
Abel said legal marijuana supply is unlikely to match demand any time soon.
“You have this great demand, and you have retailers who will have to cut hours or close for several days a week because they’re trying to limit how much product’s moving so they can stay open more continuously until the next crop,” Abel said. “That will even out in a year or so. ... I encourage all those folks who got their licenses to grow as fast as possible.”
Into the new year
For legal marijuana advocates, 2016 has been a mixed year. In the Nov. 8 general election, three states voted to legalize recreational marijuana and three for medical marijuana. However, the incoming Trump administration’s stance on the drug is unclear, though presumptive attorney general appointee Jeff Sessions has opposed legalization.
Asked if he believes the marijuana industry has permanently established itself as a legal venture, Abel — a board member of the Alaska Marijuana Industry Association and executive director of the Coalition for Responsible Cannabis Legislation — said nothing is certain.
“I feel comfortable with state politics and local politics,” Abel said. “Federal politics are a bit of a larger question right now. I wouldn’t say anything is guaranteed. But what I have learned from this process is you just don’t give up. ... When you have a business that takes two to five years to pay for, you move forward. You don’t stop because of a perceived federal threat. You move forward and involve yourself in politics to the best of your ability.”
Boyd said that while the political future of marijuana may be uncertain, its place in America’s broader culture has permanently changed.
“You know that expression, ‘an idea whose time has come?’” Boyd said. “The normalization and legalization and use of cannabis medically and as a mild intoxicant, that’s just being accepted across the board.”
Ben Boettger can be reached at [email protected]

Amid a saturated liquefied natural gas, or LNG, market and falling prices, ConocoPhillips announced Thursday that its Nikiski LNG terminal is for sale. Officials say the local economy might not be greatly impacted in the short term, though.
The natural gas liquefaction facility and terminal has been exporting LNG, mostly to a pair of Japanese utilities, since 1969. The company’s announcement marks its latest withdrawal from the Cook Inlet natural gas market. Whatever effects the plant’s sale may have on the local economy will not be immediate, according to Larry Persilly, the Kenai Peninsula Borough mayor’s special assistant for oil and gas, who said present employment and taxation at the plant won’t be affected as long as it remains open.
Though the plant was inactive for half of 2015 and has been for all of this year, Persilly said it has between 35 and 40 employees and contractors working to maintain it, who would likely remain employed if it sold. As of press time Saturday, a ConocoPhillips spokesperson hadn’t returned a request for comment.
The facility’s tax value to the borough will also be unaffected, Persilly said. According to information from the Kenai Peninsula Borough Assessing Department, the total taxable value of property owned at the plant site by ConocoPhillips and its subsidiary, Kenai LNG Corporation, is $1.6 million.
Persilly said it is unlikely that the plant could be a useful purchase for the Alaska LNG Project, which had planned a similar but larger LNG liquefaction facility and export terminal south of the ConocoPhillips plant site to receive gas piped down from the North Slope. ConocoPhillips helped plan the AK LNG project with ExxonMobile, BP, and the state of Alaska, though the future role of the non-state partners is uncertain.
“The ConocoPhillips plant is about one twentieth the capacity of what Exxon, BP and Conoco looked at to handle North Slope gas, which is a huge volume,” Persilly said. “This would not meet the needs of handling and selling North Slope gas. It’s way too small, and 50 years old. So even though it’s been kept in good condition, I’m not sure expanding it to 20 times its size is very do-able.”
Alaska House Representative Mike Chenault (R-Nikiski) said the drop in global LNG prices that may have prompted the plant’s offer for sale causes “concern not only for the ConocoPhillips LNG plant, but for any opportunity to move forward on a bigger AK LNG or (Alaska Gasline Development Corporation) project.”
“I think it just shows how tough the market is for LNG right now, and we need to be very careful how we proceed forward and the money that we spend to put forth the AGDC project right now,” Chenault said.
Asked if he planned any legislative measures to incentivize future investment in the plant, Chenault said attracting buyers isn’t the Legislature’s job, but didn’t rule out action.
“It’s a matter of looking at it and seeing, ‘Are there opportunities out there the legislature can help private industry?’” Chenault said. “And if it’s something we could do, certainly I would push for it.”
Taking a broader view, Chenault said the prospective sale is consistent with a pattern of oil and gas development in which assets established by larger global companies eventually pass into the hands of smaller, newer ones.
“Most oil and gas fields go through these stages where the majors come in and start developing a field, and as the field starts to dry up, you see smaller independents start to move in with a smaller overhead,” Chenault said. “That’s the normal progression of an oil or gas field.”
ConocoPhillips’ announcement of the sale states that the company is focusing on its North Slope operations. In July 2015, ConocoPhillips announced plans to sell its two Cook Inlet leases, the North Cook Inlet gas field and its share of the Beluga River gas field, which it shared with Hilcorp Energy.
In February 2016, the Anchorage-based utilities Municipal Light and Power and Chugach Electric Association bought ConocoPhilips’ portion of the Beluga River field, and in October 2016 Hilcorp bought the North Cook Inlet field. Worldwide, ConocoPhillips is looking to cut its costs. In a Nov. 10, 2016 press release, the company announced a $5 billion-$8 billion divestiture program, which the release stated “will focus primarily on North American natural gas.”
Ben Boetgger can be reached at [email protected]

As Homer Electric Association proceeds with its election to withdraw from the oversight of the Regulatory Commission of Alaska, HEA subsidiary Alaska Electric and Energy Cooperative is also planning a deregulation election.
The subsidiary legally owns HEA’s generation and transmission infrastructure and operates as a separate cooperative with HEA as its sole member. According to an HEA information sheet, AEEC has a nine-member board of directors who historically have been identical to the HEA board of directors, and also shares HEA’s general manager.
Alaska statute allows a publicly regulated utility cooperative to withdraw from regulatory oversight by a majority vote of its members. HEA mailed the first ballots in its deregulation election on Oct. 5, and members will return the final ballots by Nov. 27 to the regulatory commission, which will count the ballots and announce the results in December.
The commission announced AEEC’s petition to deregulate on its website Friday. According to the commission’s notice, both companies’ board of directors unanimously voted for the deregulation election at their May 10, 2016 meeting and notified the RCA on Oct. 21.
Following Alaska statute, the AEEC will hold a public meeting on the deregulation on Dec. 13 at 3 p.m. in HEA’s Kenai office. The HEA board of directors, as the representatives of AEEC’s sole member, will receive the ballot eight days later, on Dec. 21.
According to an HEA information sheet, AEEC was formed in August 2001 after the dissolution of the Alaska Electric Generation and Transmission Cooperative, a subsidiary group that played a similar infrastructure-owning role with HEA and the Matanuska Electric Association as its two members.
In a previous Clarion interview, HEA and AEEC General Manager Brad Janorschke said AEEC is “a financial tool to allow us to remove the upward pressure on rates” by borrowing money on more favorable terms.
The cooperatives together hold about $372 million in debt. Janorschke said HEA owes about 60 percent of this debt to the National Rural Cooperative Finance Corporation, a non-profit finance corporation that lends to electrical cooperatives, while the rest — about $150 million — is owed by AEEC to the U.S Department of Agriculture’s Rural Utility Service. Janorschke said the company took on most of this debt between 2011 and 2014 when HEA was building or acquiring three gas-fired power plants in its Independent Light project.
Janorshke said power lines are expensive to insure because they are relatively fragile and exposed to the elements. Insurers for transmission infrastructure therefore require owners to generate greater revenue in order to demonstrate their ability to pay insurance, which would have raised HEA’s rates if ownership of the lines hadn’t been assigned to a different entity.
Janorschke said the arrangement with AEEC saves HEA about $2.5 million a year. According to the HEA information sheet, two cooperatives’ respective lenders require HEA to earn 35 percent more revenue than its debt obligation, while requiring AEEC to earn 5 percent more than its debt obligation.
Taking on debt
AEEC’s debt acquisition has been controversial in the past. In November 2010, the watchdog group HEA Members Forum sent an informal complaint to the RCA about an April 2010 AEEC resolution that allowed its four officers — president, vice president, secretary, finance director and general manager — all positions then filled by the same people who held them at HEA — to borrow up to $180 million for 35 years.
“(The resolution), substantially, authorizes any one or all of the individuals listed to act at their individual discretion to commit the HEA financially as they determine to be in the best interest of the HEA,” the group wrote in a November 2010 letter to the regulatory commission signed by eight HEA members. In January 2011 the Members of Homer Electric Association, Inc. called for a formal RCA investigation into the relationship between HEA and AEEC, and the AEEC’s authority to take on debt. In the request, David Bear, a member of the association, wrote that “the present relationship between HEA and AEEC serves to preclude meaningful oversight by HEA member/owners...”
The regulatory commission denied the investigation request in an order issued July 19, 2011.
“We fail to see how ... concerns over the debt limitations of HEA and AEEC would warrant an investigation by the commission at this juncture,” the order states. “The adoption of debt caps for HEA and AEEC are matters for the Boards of Directors of HEA and AEEC, not the commission. We find that MHEA’s allegations concerning HEA and AEEC’s debt limitations are internal cooperative governance issues that do not warrant an investigation by the commission.”
The possibility of AEEC following HEA’s deregulation election was discussed at an RCA meeting on Oct. 12. Bob Shavelson, executive director of conservation nonprofit Cook Inletkeeper and a signer of the HEA Member Forum’s 2010 RCA complaint, submitted questions to the commissioners at that meeting, some of which were about AEEC.
“Will HEA — which solely controls AEEC ­— turn right around and deregulate AEEC?” Shavelson wrote to the commission. “If so, why didn’t HEA tell its members in the official notice of the deregulation election? How would a deregulation vote affect AEEC financing? Do AEEC’s financing institutions view deregulation as a good thing or a bad thing in regard to debt service, and why?”
RCA consideration
In the Oct. 12 RCA meeting, Assistant Attorney General Stuart Goering was asked about the possibility of AEEC deregulating.
Goering cited as precedents two previous RCA cases which he said suggested “that generation to transmission cooperatives that are owned either by a single member or by a small number of utility members would have to have essentially a pass-through election where the actual consumers of those utilities would vote to deregulate as opposed to having simply the sort of formal members of the cooperatives vote.”
One of the decisions Goering cited was a 1985 case in which AEEC’s predecessor Alaska Electric Generation and Transmission Cooperative — with HEA and Matanuska Electric Association as its two members — sought to exempt itself from RCA oversight to order to more quickly install a generator.
The decision by the RCA predecessor agency Alaska Public Utilities Commission concluded “that it would be appropriate to place (the cooperative) on notice that, pending further consideration and order of the Commission, any election to be exempt from the Alaska Public Utilities Commission Act (AS 42.05) must be based on the vote of the consumers of the members of (the Alaska Electric Generation and Transmission Cooperative).”
“The Commission has preliminarily examined the applicable statutes, and believes that these statutes do not clearly establish whether an election by (the cooperative) to be exempt from regulation must be based on a vote of its two members, through their Boards of Directors, or on a vote of the consumers of HEA and (Matanuska Electric Association),” the decision states. “It does, however, seem clear that the Legislature contemplated an election by the actual consumers, because at the time the statute was passed no generation and transmission cooperatives existed, and all cooperatives had actual consumers as their members.”
Ben Boettger can be reached at [email protected]

The Kenai Municipal Airport’s freshly paved tie-down lot and taxiways were ceremonially put into operation with a ribbon-cutting on Thursday.
Kenai Airport Manager Mary Bondurant said that of the Kenai Airport’s 14 taxiways (designated A through M, or Alpha through Mike) that let planes travel between hangars and the runway, three have been rehabilitated for roughly $2 million, $1.9 million of which was granted by the Federal Aviation Administration.
When the Kenai airport was built as a World War II-era military airbase, its runways and taxiways were laid with more concern for haste than longevity.
“It looks like they (Kenai Airport’s runway builders) dug some of the fill out of the taxiway and pushed it over there for the old runway, and then back-filled with garbage — trees, mud, swamp and moss,” said Jim Bielefeld, owner of the charter flight business Kenai Aviation.
The old taxiway has since been buckled by the seasonal freezing and thawing of the ground, creating dips, mounds and cracks.
Bielefeld, who inherited Kenai Aviation from his father Robert Bielefeld, said he grew up on the Kenai airport and remembers learning to ride a bike on the old taxiway. He estimates he now takes planes down Taxiway G from Kenai Aviation’s lot to the runway about three to five times per day and said the trip has sometimes been rough.
“There were times when going through a bump, all three wheels would be off the ground, as well as the tail skid,” Bielefeld said. “It was a real dip. But no damage.”
Engineer Kirk Hollingsworth of the Kenai-based engineering firm Wince-Corthell-Bryson led the renewal project. He said the old taxiway’s susceptibility to frost heave was due to the foundation of buried debris below it, which persisted despite the various repavings — most recently in the 1980s — that were laid on top of it. For the present refurbishment, Hollingsworth dug out the foundation of rotten wood and debris and replaced it with sand and gravel — materials which Hollingsworth said hold little water and so are less likely to frost.
Lighting design was another part of the project. The marker lights bordering the taxiway were previously mounted on two-foot tall posts.
These were replaced by lights embedded in the pavement, which are in no danger of being knocked over by trucks or snow plows.
The lamp posts that lit the tie-down lot were also replaced with posts that are shorter and lamps that are more directional, so as not to cast light into the surrounding neighborhoods. The wiring of the old lightpoles was another relic of old engineering practices — digging beneath, electrical contractor Derek Leichliter of Legacy Electric found them wired directly into a Homer Electric Association power transformer with no cut-off point, creating the potential to damage the transformer and cause a power outage if the airport had ever produced a surge.
Kenai airport operations specialist Matt Landry said replacing the high-pressure sodium lightbulbs of the old lightpoles with LEDs was not only more energy efficient, but saves on maintenance. Landry counted 507 lightbulbs on the airfield that his department is in charge of changing.
The 354 lining the taxiway are LEDs installed about 11 years ago, while the 103 lining the runway are older incandescents. Landry said the only LED bulbs he’s changed since their installation have been damaged ones, while the incandescent lightbulbs burn out and needed replaced about every 4 months.
Though most of the renovation was funded by the FAA, Bondurant said the remaining $130,810 — equal to 6.25 percent of the project cost — came from Kenai’s Airport Improvement Capital Project Fund and was unanimously appropriated by the Kenai City Council at their meeting on May 4, 2016.
Bondurant, Bielefeld, Hollingsworth, Leichliter, and other contractors and airport employees gathered on the tie-down lot for Thursday’s ceremony. Moments after Bondurant and Kenai City Council member Henry Knackstedt cut a red ribbon over the taxiway, Bielefeld parked one of his company’s single-engine planes in the new tie-down lot. Getting out, he examined the fresh pavement.
“I’d like to come out here and ride my bike on this,” Bielefeld said.
Ben Boettger can be reached at [email protected]

ANCHOR POINT — BlueCrest Energy ceremonially opened their Hansen Production Facility, an oil wellpad on the shore of Cook Inlet near Anchor Point.
A small group of guests sheltered from the drizzle under a canopy in the middle of the 38-acre facility’s gravel wellpad on June 25. Speakers included Sen. Lisa Murkowski, state Sen. Peter Micciche, R-Soldotna, and BlueCrest President Benjamin Johnson, who took turns behind a podium with a low array of girders, tanks and pipes stretching behind them and a humming natural gas-fired power turbine underlying their words.
To the south, the 30,000 feet of steel tubing that will case two future oil wells lay stacked in a row that stretched across the pad.
“This is a state that was built with oil and gas, and will continue to be,” Micciche said in a speech before a ribbon-cutting ceremony. “For those that believe we are ready to move beyond petroleum in our economy and what powers our incredible nation, we know that’s not the case. Although times are changing, and we’re suffering from a low commodity price right now, we know things will eventually improve.”
The one currently-producing well on the pad — an exploration well drilled by ConocoPhillips in 2001, putting out about 250 barrels of oil a day — was shut down for the ceremony and subsequent bus tour of the complex.
During that tour, Murkowski asked BlueCrest production engineer John Martinek when the most recent producing oil well was drilled in Cook Inlet. Martinek estimated it was 16 years ago. James Carson, Canrig Drilling’s Alaska District Manager, was along for the tour. He guessed the well was in the Redoubt Shoal prospect, drilled in 2000 from the Osprey platform by Forest Oil.
The 10 producing wells BlueCrest intends to drill from the Hansen pad will be the first since then. According to a BlueCrest information sheet, within five years the company hopes to be producing 17,000 daily barrels of oil, trucking it north to sell to Tesoro’s Kenai refinery.
Although BlueCrest’s underground work has yet to be done, the above-ground equipment is already functioning. Martinek said the facility on the wellpad was built in about nine months.
“Back in June (2015) it was a parking lot,” Martinek said of the site, just north of Anchor Point near Sterling Highway mile 151. “We’d just started driving piles to house our pipe rack. We went into our foundations in August, we started bringing in equipment in September, and the last day of March we brought on our first production.”
Martinek described the wellpad structure as “a pretty complex facility that does a real simple thing.”
“It just separates the oil from the water and the gas,” Martinek said. “But a lot of technology goes into that.”
The oil, natural gas and water are all found within the folded sedimentary layers of the Cosmopolitan formation, a dome-like feature approximately 7,000 feet below the floor of Cook Inlet and about three miles off shore. BlueCrest’s plan calls for a directional drill to penetrate the formation and for the sediment to be opened with hydraulic fracking — a process not used before in Cook Inlet, which would inject a high-pressure mix of sand, water, and chemicals into the well to open cracks through which oil will flow.
Many particulars of BlueCrest’s fracking plans — such as the volume and source of the water used, and where it will disposed of afterward — remain undecided, and the fracking plan has been criticized by local activists and Center for Biological Diversity.
Johnson said BlueCrest doesn’t presently have any fracking equipment on site — the work will be done later by North Slope-based contractors after the wells are drilled.
The drill rig sitting behind the separation complex presently consists of a 30-foot tall platform. When completed with a 180-foot derrick being shipped from Texas, it will be the largest on-shore drill rig in Alaska, Martinek said.
The rig is also self-propelled, using hydraulic arms to move itself on skids along a row of 20 future wellheads, spaced about 10 feet apart. Ten of these wells will produce oil, while the others will pressurize the reservoir with injections of water. Martinek said the rig could travel between well heads in about a half hour, avoiding the more common practice of disassembling a rig to move it between wells.
According to a BlueCrest information sheet, the rig will drill 24 hours a day for around five years to complete the wells — although Johnson said oil prices and the availability of tax credits could change these plans.
“We can stop drilling if prices were to drop,” Johnson said. “Unlike many companies, we have the ability to pause.”
While the oil emerging from the wells will be sold, the natural gas that comes with it will burnt on-site in a pair of generating turbines to power the facility itself. This generating gas is presently being supplemented with purchased gas from Enstar Natural Gas Company, delivered through a pipeline running along the Sterling Highway. Martinek said after the next well is drilled, it will produce enough gas for the facility to be powered without gas from Enstar. In the future, BlueCrest plans to sell gas to Enstar via the same pipeline now delivering to the Hansen facility.
Large-scale gas production won’t be possible through the on-shore wells, but will require off-shore drilling. Although oil, gas and water are naturally mixed inside underground reservoirs, those with a greater concentration of gas tend to lie higher in a formation because of their lesser density. This makes them unreachable with the directional drilling technique BlueCrest is presently using. BlueCrest’s plans to drill three off-shore gas wells are suspended due to the decreased availability of state tax credits to subsidize production.
In addition to the drill rig and separation machinery, the site contains a control room and a 50-bed dormitory for the nine operators, four guards, drillers and other staff. Martinek said “all the long-term workforce is local labor here,” adding that eight of the nine operators are from the Kenai Peninsula and six had graduated from Kenai Peninsula College’s process technology program.
One of these is operator Jessi Hahn, who lives in Homer and graduated from KPC’s process technology program in December. The BlueCrest job is Hahn’s first oil project in Alaska. She said the career is difficult to enter right now, and she was glad to have been hired soon after graduating.
“It gives an opportunity for people coming out of college to have a job and start training and becoming good at it,” she said.
Jayce Roberts, another KPC Process Technology graduate working as an operator at BlueCrest, said operators work 12-hour shifts, two weeks on and two weeks off. Though he had done other oilfield jobs, this is his first job as an operator. He said the BlueCrest facility’s location made it a desirable place to work.
“I live right in Kenai, so it’s a great opportunity versus having to fly to the North Slope, or take a helicopter to a platform or fly across the Inlet,” Robertson said. “I think it’s just a lot more convenient. I’ve done work in remote locations, and everything about it is logistically difficult ... There’s a huge advantage to being right here on the highway system.”

KENAI — Kenai’s first commercial marijuana business — Red Run Cannabis Company — has permission from the Kenai Planning and Zoning Commission to open a cultivation facility and shop beside the Spur Highway in Kenai’s Thompson Park subdivision, an area where commercial zoning sits adjacent to residential zoning.
The store’s proximity to the neighborhood had led to opposition from some owners of nearby houses.
After delaying Red Run’s permit at a March 23 meeting, the commission voted 5-1 to grant the permit on Wednesday. Commissioner Glenese Pettey voted against the permit, saying the store “is not in harmony with the surrounding properties, and it would be detrimental in the aspect of property values.”
Commissioner James Glendening was absent.
Red Run’s prospective location is an abandoned gas station and convenience store in a highway bordering strip of limited commercial zoning. The property’s owner Roger Boyd, a Red Run co-founder with Eric Derleth and Marc Theiler, said that his business would be appropriate for the zone, which he said was intended to create a transition between commercial and residential neighborhoods. Boyd also addressed fears that property values would be damaged by a nearby marijuana store.
“The truth is that no one knows what the impact on property values would be,” Boyd said. “I would contend that our proposed business is no more a detriment to surrounding property values than the liquor store that was there for years, or the Eagle club down the street.
“One thing I’m certain of, though, is that if you take this building that’s been empty for a couple years, a little grown-up around it, and we go in there and clean it up and put a vibrant business in it, that will have an effect of improving property values of both the residential and commercial properties in the neighborhood.”
Another frequently-voiced objection to the business was that it would lead to a local increase in trespassing and crime. Theiler, who lives near the shop location and said he uses the bike path near the property frequently, said he has seen used condoms and syringes littering the alley behind the currently-vacant building, where the gas station lot borders the yard of Christine Cook, who has opposed the permit over safety concerns.
Theiler said Red Run intended to fence off the rear alley. He argued that with the building occupied and with the light and camera systems the owners intend to install, illicit activity in the neighborhood would go down.
Cook said she wasn’t ideologically against commercial marijuana but opposed locating it in a narrow area of commercial land close to a neighborhood.
Patricia Patterson, owner of Soldotna’s Lucky Raven Tobacco store, said Kenai’s marijuana regulations had played a role in creating the disagreement between residents and the business by limiting the possible locations a marijuana business could operate in town.
In early 2016, Kenai passed laws creating 500 foot set-backs for marijuana businesses from recreation centers, churches, correctional facilities, or drug abuse treatment centers, and doubling the state’s 500 foot setback from schools to 1000 feet, as well as choosing to measure the setbacks in a more restrictive way than the state.
The planning and zoning commission created early drafts of the Kenai marijuana rules, which were amended and passed by the city council on Jan. 20.
“It’s true — we have a lot of retail, a lot of commercial along the Spur highway with houses close by,” Patterson said. “That is the face of our community. I think it is something that might be hard for the neighbors to see. So it does come down to ‘that is the way we zoned.’ That was the recommendation, to do these big circles and big buffer zones that kept a lot of the (marijuana) retail out of the city of Kenai and put them towards the outside of Kenai. That was a choice that came from this committee.”
Pettey said she intended to vote according to what she described as the original intent of Kenai’s marijuana regulations — to exclude cannabis businesses from residential areas, which she interpreted to include Red Run’s proposed location.
“I believe it was the intent not only of planning and zoning but of city council to keep retail marijuana stores out of residential areas,” Pettey said. Bloom said he would “respectfully disagree, to some extent.”
“By our planning and zoning table, a retail establishment would be allowed on this property by conditional use permit,” Bloom said. “That intent was to keep it out of residential neighborhoods, and I’d have to say that that property is not located in a residential neighborhood. It’s adjacent to one, but not within the residential neighborhood.”
Commenting before the vote, some commissioners said they would vote for the permit based on its compatibility with the zoning code, but against their personal inclinations — a feeling expressed by commissioner Kenneth Peterson, who said he felt as if he was “playing devil’s advocate” by voting in favor.
“When this first came up, as a resident of the city and a parent, I wasn’t sure how I was going to feel about it,” said commissioner Diane Fikes. “And then sitting on the commission, and having to realize that the city had said yes, the state had said yes, we want to do it... What we’re here for today is nothing on a moral or civic issue, but everything on a land use and a zoning issue. I believe everything has been met, and all the questions I have have been answered.”
The Kenai conditional use permit will be open for appeal for 15 days. Red Run’s next license will come from the state Marijuana Control Board, which posted notice that the license had been received on Feb. 24, 2016. During the state licensing process, the Kenai city council will be able to vote on whether or not to object to the license. An objection would cause the state to deny the license. The council would also be able to object during Red Run’s yearly license state renewal. Theiler said that if everything goes according to plan, Red Run could have product for sale in September 2016.
Reach Ben Boettger at [email protected]

Gold from old mining claims on the eastern Kenai Peninsula may have a new path to the market if a proposed gold extraction mill begins grinding in the hills near Seward this summer.
The envisioned Sable Crown Gold Mill is a project of the privately-owned Diamond Gold Corp., whose president Ed Ellis will present his mill plans in an open house on Saturday at Moose Pass’s Trail Lake Lodge, from 11 a.m. to 6 p.m.
According to an announcement on Diamond Gold's website, the mill will crush 100 tons of gold-quartz ore per day. Ellis plans for it to begin processing 40 tons per day by early summer before expanding to full capacity.
Ore will be supplied by small mines around Seward and the Port Wells area of Prince William Sound. Ellis, who has owned mining claims near Cooper Landing since the 1970s, said local mines are a historically proven source. However, extracting gold from the ore produced by these mines has been a challenge.
“Standing alone, the mines are too small to support the infrastructure of a mill,” Ellis said. “However, they could sell their ore to a custom mill. Then it becomes very economic for these small mines.”
Ellis said it was common in the past for mines to have their own mills working intermittently, crushing ore into fine particles that could be sifted for valuable minerals. However, the economic rationale for creating a larger, centralized gold mill disappeared in the late 20th century, along with many of the miners.
During World War II, many Alaska mines were closed by government order to redirect equipment and manpower toward the military. Through the 1940s and 1950s, the price of gold remained around $35 an ounce, according to the National Mining Association.
“After the war, the price of gold never rose,” Ellis said. “And of course, wages were in demand for construction in Alaska for the buildup of the military. Small mines just couldn’t compete for the wages, with the gold not going up.”
When Ellis begin mining in the early 1970s, gold prices were entering a swift rise that has continued to the present. Ellis believes the value of gold — about $1,200 per ounce — is high enough to make the Sable Crown mill a sound prospect. He said the mill will acquire ore in a variety of ways.
“Some of the miners will want to do their own mining because they’re independent, and that’s great,” Ellis said. “With some of them we’ll go in and lease it, and we’ll work it ourselves. Then I have prospects I found 40 years ago that I know are good, and we’ll be mining those ourselves. Some we’ll lease, some we’ll just purchase the ore delivered to the mill, and some we’ll mine ourselves.”
David Moore, a third-generation eastern peninsula miner, refers to the pre-World War II miners as “the grandfathers.” He estimates that there were 280 small mines active in the area around Seward before the war. He presently owns two of them: the Primrose mine, visible from the Lost Lake hiking trail, and the Devil’s Club mine. Moore said he restarted mining at Devil’s Club about a year ago after recovering from an illness. The Primrose he intends to lease to Diamond Gold.
“I, as one of the owners, am interested beyond a doubt,” Moore said of Ellis’ mill.
Ellis plans to build the mill on private land in either Seward or nearby Crown Point, and estimated that it will be operational for 10-15 years. He said the mill will have a low environmental impact because of the nature of the gold-quartz ore it will be processing.
Ellis said particles of gold are physically trapped inside the quartz of gold-quartz ore rather than being bound to the material in a metallic alloy, as gold is in some other ores. Extracting the gold therefore requires physical grinding and sifting rather than a chemical process. Ellis said the mill will not require cyanide or mercury, hazardous chemicals used in some extraction process. He estimated 50 percent of the gold could be recovered by the mill and said the remnants of the process, a dense sand-like powder called concentrate, will be sold overseas for further gold recovery. He added that all water used by the mill will be recycled.
According to Diamond Gold’s website, the mill will provide between 20 and 25 jobs with a $2.5 million payroll. Ellis said the company is taking applications and that he will talk about employment at the open house.
“It’s still a small operation compared to the giant mines in the Interior of Alaska, but it’s going to be a very good little project,” Ellis said.
Reach Ben Boettger at [email protected]

KENAI — Local representatives of the Alaska LNG Project said that although their leaders have spoken of possible delays, employees of the project remain set on smaller steps before them.
These steps include creating final drafts of impact reports and completing property acquisitions for the prospective pipeline’s liquefaction facility and export terminal in Nikiski.
On Feb. 17, representatives of the Alaska LNG Project partners — the State of Alaska, BP, ExxonMobil, and ConocoPhillips — said at an Anchorage press conference that uncertainty over the global LNG market may bring changes to the larger structure of the project. In a public meeting Saturday at the Kenai Visitor Center, Alaska LNG Community Stakeholder Advisor Josselyn O’Connor said these possible changes were not prompting hesitation with the project’s work.
“Our marching orders are to get through and complete pre-FEED,” O’Connor said, using the project’s acronym for preliminary front-end engineering and design — the preparatory work needed to decide whether to invest in building the 806-mile pipeline to carry natural gas from the North Slope.
Since 2012 the Alaska LNG partners have invested approximately $500 million in conceptualizing the pipeline, including $230 million budgeted for 2016, and are expected to make a further investment of up to $2 billion if they continue to actual engineering and design. The Alaska LNG Project has estimated it will ultimately spend between $45 and $60 billion on its facilities.
“We know there’s a lot of noise around the project right now,” O’Connor said. “But we’re committed to pre-FEED. I think the owners stood up and said they’re committed to pre-FEED. We’re also looking at optimization: how do we get the cost of this project closer to the lower end of that price ticket? The other big thing is the resource reports. Those have to line up.”
Alaska LNG will have to submit 13 reports of the project’s estimated effect on the local environment and culture to the Federal Energy Regulatory Commission, a national licensing authority.
O’Connor said she expects the reports to be submitted in summer 2016.
In response to an audience question, O’Conner said Alaska LNG will not need to complete its land purchases for the Nikiski facility in order to continue FERC licensing. She said the project has purchased about 570 acres and will eventually need to buy between 800 and 1,000 acres for the Nikiski terminal.
Larry Persily, a former federal oil and gas coordinator and current advisor to Kenai Peninsula Borough Mayor Mike Navarre on LNG issues, said FERC would consider Alaska LNG’s application even if its acquired land is “a little bit of a jigsaw, and there’s a few pieces missing.”
“When the project applies to the Federal Energy Regulatory Commission, they have to show they control the site,” Persily said. “The law does not require that they own 100 percent of the property, but they’ve got to show federal regulators that they have enough of the property under contract purchase option to show they control it.”
He added that at least one prospective LNG project has been denied a FERC license for lacking sufficient control of property.
When asked by an audience member what the project might do with the land if it does not reach the building stage, Alaska LNG Project Advisor Jeff Raun was uncertain.
“In terms of our property management plan, I’m not sure of a clause that says ‘what do we do if...?” Raun said.
In an interview afterward, Persily said that in the event the Alaska LNG Project decides not to build, recouping the land investment would be “the least of their worries,” and the property tax the project would continue to pay on the unused land would be a small part of its overall expenses.
At the meeting’s conclusion, Persily also commented on the presently oversupplied global LNG market, in which major buyers in South Korea and Japan have dropped their imports by around 14 percent over the past two years, according to an email update by Persily.
“The only LNG export projects anywhere in the world in the past few years that have gone to a final investment decision — because the market is so bad — have been the ones on the U.S Gulf Coast, where they already had an LNG import terminal in place,” Persilly said Saturday.
In that case, he said exporting had been viable because it only required a slight reconfiguration of an unused export terminal.
The U.S largely stopped importing natural gas after the technique of extracting gas from shale was perfected in the 2000’s, creating a new domestic supply. He added that the only other recent new LNG exporter is an effort subsidized by the Russian government.
In a later interview, Persily said that given the value of the North Slope gas Alaska LNG wants to market, it’s unlikely Alaska’s pipeline and terminal will never be built.
“I don’t think it’s a question of not building it, but when,” Persilly said.
Reach Ben Boettger at [email protected]

KENAI — Cook Inlet Natural Gas Storage Alaska is contesting a revenue-sharing scheme that would allow it to sell 2 billion cubic feet of natural gas found in its underground storage facility if it gives 61.1 percent of the revenue to its client utilities.
CINGSA is appealing for the Alaska Superior Court to overturn a Dec. 4, 2015, decision by the Regulatory Commission of Alaska, the state entity that oversees public utilities.
The Regulatory Commission allowed CINGSA to sell 2 billion cubic feet of the 14.5 billion cubic feet of gas it had discovered while drilling a storage well in 2012 and keep 13 percent of the profits.
The rest would be divided among the four utilities that hold 20-year contracts to store gas in the CINGSA facility — Homer Electric Association, Anchorage’s Municipal Light and Power, Chugach Electric Association, and CINGSA’s sister company ENSTAR — according to the percentage of stored gas each owns.
CINGSA representatives had earlier argued before the Regulatory Commission that their company had sole property rights over the gas and could sell it as they wished, and later presented a scheme in which CINGSA split profits with its clients half and half.
The Regulatory Commission rejected both after hearing arguments from the client utilities that their investments in CINGSA storage contracts had made the facility — and the discovery — possible, and that the removal of the found gas would decrease well pressure required to extract stored gas, constituting a risk deserving a return in revenue from the gas sale.
CINGSA and ENSTAR spokesperson Lindsay Hobson said CINGSA would argue its original contention: that it has a right to all the revenue from the gas it found.
“We’re appealing on the basis of our litigation position, and our litigation position was 100 percent of the proceeds of CINGSA’s asset to remain with CINGSA as the property owner,” Hobson said.
CINGSA’s statement of points on appeal contends that in creating the revenue-sharing scheme it did, the Regulatory Commission “effectuated an unconstitutional taking without just compensation by ordering CINGSA to distribute to third parties proceeds of the sale of assets undisputedly owned by CINGSA” and that it did so “without reference to any law or legal principle.”
The appeal was filed Jan. 4 and initially assigned to Judge Catherine Easter, who was peremptorily disqualified after a motion by CINGSA attorney Matthew Findley. Alaska court rules allows a party to a lawsuit to disqualify a judge.
The case was then assigned to Judge Pamela Washington, who was similarly disqualified by a motion from ENSTAR attorney David Shoup. As of Jan. 26, the case is assigned to Judge Eric Aarseth.
Hobson said CINGSA had not estimated the value of the 2 billion feet of natural gas.
“Right now, with prices, it’s too speculative for us to say the value of something we can’t sell today,” Hobson said.
Reach Ben Boettger at [email protected]

KENAI — Prospective marijuana businesses in Kenai will have to observe 1,000-foot setbacks from schools, 500-foot setbacks from other sensitive areas — measured two different ways — a list of zones in which they can establish themselves with permission from the Kenai Planning and Zoning Commission, and two zones in which one business type can operate unpermitted.
The Kenai City Council amended and unanimously passed the city’s final marijuana regulations during a four-and-a-half hour meeting Jan. 20.
At the final meeting in which they could pass law that would be in effect before the state begins accepting commercial marijuana license applications on Feb. 24, the council edited and passed a set of marijuana regulations originally created by the Kenai Planning and Zoning commission.
The regulations mandate minimum distances between marijuana businesses and schools, recreation centers, churches, correctional facilities, or drug abuse treatment centers. In the case of schools, this setback is 1,000 feet, measured from the outer wall of the marijuana business’s building to the property line of the school. The 500-foot setback from recreational centers is measured the same way.
The 500-foot setback from churches, correctional facilities, and drug abuse treatment centers is measured from the marijuana business’s outer wall to the nearest pedestrian entrance.
Five principals from area schools testified at the meeting to their personal support of the 1,000-foot school setback.
The setback, which is double the state-mandated 500-foot school setback, was recommended by Kenai City Attorney Scott Bloom, who said it complied with the federal Drug-Free School Zone Act.
Marijuana establishments will also be constrained by zone.
Of the four state-licensed establishment types, only one will be allowed without planning and zoning permission, and only in two zones.
Establishments licensed to test marijuana for contamination and potency will be allowed in Kenai’s light industrial zone — concentrated near the airport and a spot along the Spur Highway at the northern edge of town — and the heavy industrial zone — located near the Kenai River along Bridge Access Road.
Holders of the other license types — for marijuana cultivation, retail, and the manufacture of marijuana products such as concentrates and edibles — will have to seek conditional use permits from the planning and zoning commission before opening in allowed zones.
The change allowing unpermitted testing in industrial zones was proposed by council member Bob Molloy and passed unanimously.
Motions by council member Terry Bookey to also allow planning and zoning-permitted cultivation and retail establishments in the industrial zones failed, with council members Brian Gabriel, Henry Knackstedt, Tim Navarre, and Kenai Mayor Pat Porter voting against both motions.
Bookey made a successful motion to allow retail establishments with planning and zoning permission in the central mixed-use zone, where they had been banned under the planning and zoning commission’s draft regulations.
The central mixed-use zone is located around the intersection of Bridge Access Road and the Kenai Spur Highway, and north of the Kenai Spur Highway across from Old Town.
A resolution passed by the seven members of the Kenaitze Tribal Council requested that the Kenai City Council exempt Old Town Kenai, defined in the Kenaitze resolution as the area between Broad Street and Petersen Way, from all four commercial marijuana license types.
The resolution stated “the Kenaitze Tribe has a firm belief that substance use negatively impacts our traditional ways of living, culture, and values” and referred to the tribe’s large presence in Old Town Kenai through its Dena’ina Wellness Center and Tyotkas Elder Center.
Although the zone Bookey proposed opening to commercial marijuana lies near Old Town Kenai, it is mostly separated from it by the Kenai Spur Highway, with only a few highway-fronting lots directly bordering Old Town.
Bookey said these would be accessible by vehicle from the highway, but not from Old Town. The change was made with opposing votes by Gabriel and Porter.
Bookey also made a successful motion to allow small-scale marijuana growers to operate with conditional use permits in residential and limited commercial lots less than 40,000 square feet, which was opposed by votes from Navarre, Porter, and Gabriel.
Bookey, who had recently been traveling out of state, said he had seen marijuana regulations at work in Washington and Oregon, and the experience — along with the finalized set of Alaska regulations expected to be signed officially by Lieutenant Governor Byron Mallot on Jan. 24 — had reassured him that marijuana could be commercialized safely.
“With the regulation that’s going to be put forth for cannabis, I’m less scared than I was before — and I wasn’t that scared to begin with — about it getting to unintended users,” Bookey said.
Reach Ben Boettger at [email protected]

KENAI — After considering several possible paths for a new highway section around Cooper Landing, the Alaska Department of Transportation named its preferred path for the new road on Dec 11.
The proposed 5.5-mile bypass will depart from the existing Sterling Highway around milepost 52 in Cooper Landing and cross to the north side of the Kenai River via a bridge to be constructed about a half-mile east of that point. A second new bridge will take it over Juneau Creek, and on the north shore of Kenai Lake it will connect with the existing highway around milepost 46.
Passing through uphill land to the north of Cooper Landing, the proposed alternative will avoid a section of the present Sterling Highway that is winding, narrow, and slow. The speed limit of this section is 35 miles per hour, encouraged by Cooper Landing residents whose homes and businesses sit close to the highway with signs that read “We drive 35.”
On either end of the new bypass, existing highway will also be replaced for a distance totaling 8 miles. Department of Transportation spokes person Shannon McCarthy said the road’s age makes it less safe.
“The road itself is fairly old, both in its actual age and its design age,” McCarthy said. “This section of the Sterling doesn’t meet modern highway design (standards). It doesn’t have adequate shoulders, it doesn’t have a good clear zone, which you find on most modern highways.”
Clear zones are empty space bordering a highway, which McCarthy said are important because “if someone did leave the road for some reason, we’d want that vehicle to be able to come to a stop safely without hitting an obstacle or a steep embankment that might flip a car.”
An existing bridge crossing the Kenai River near milepost 53, labeled on a Department of Transportation map as the Schooner Bend Bridge, will also be replaced.
The Department of Transportation has been studying Cooper Landing bypass proposals since at least 1994, according to previous Clarion reporting. At that time, the department named a preferred route that passed through wilderness areas. According to McCarthy, the new preference does not have that problem.
“The routing avoids impacts to the Resurrection Pass Trail, the Juneau Falls Recreation Area and important cultural properties, and avoids using designated wilderness land within the Kenai National Wildlife Refuge,” McCarthy wrote in a press release.
According to the project’s draft supplemental environmental impact statement, the road will affect 126 acres of Kenai Peninsula Borough Land, 90 acres of federal land, and 43 acres of state land. Less than 1 acre of private property will be affected.
McCarthy said the “cultural properties” referred to in the release were areas important to Native Alaskans, which Department of Transportation had been asked to avoid.
The new section of the road will cross the Bean Creek hiking trail. McCarthy said the department has yet to decide how, saying it was a decision “we will address in the design process.”
According to the impact statement, the Department of Transportation estimated the road will cost $303.5 million to build, and $23.8 million to maintain over 20 years.
It is still possible that the route could change before the Federal Highway Administration makes a final decision, which according to the press release, is expected in 2016. McCarthy said there will be an opportunity for the public to submit comments before the decision.
“Both the Alaska Department of Transportation and the Federal Highway Administration identified this as the alternative they’d like to explore further,” McCarthy said. “What you’ll see is perhaps some tweaks to it, but moving forward, I think this alternative is the one they’ll build up and explore in terms of design.”
After design and federal environmental permitting, the road could be constructed in 2018.

NIKISKI — Nikiski residents gathered at the Nikiski Recreation Center on Nov. 12 for another discussion on the local effects of the Alaska LNG Project — hosted this time not by AK LNG staff, but by the Kenai Peninsula Borough.
Borough Mayor Mike Navarre and Larry Persily, the mayor’s special assistant on oil and gas projects, gave their perspective on the project in an expansive question-and-answer session that ranged from the Kenai Spur Highway relocation project to Navarre’s role on the state Municipal Advisory Gas Project Review Board to the scope of future property purchases in Nikiski.
Navarre and Persily, whom the Borough hired in March 2015 to monitor the LNG project, plan to host talks in Nikiski every second Thursday of the month. The next is tentatively scheduled for Dec. 10.
Persily began by outlining the LNG project’s summer activity in Nikiski, where the project plans to end its natural gas pipeline from the North Slope in a liquefaction plant and export terminal to be built on 800 or 900 acres of Cook Inlet-fronting land, near ConocoPhillips’ current LNG export terminal, between miles 19.5 and 21 of the current Kenai Spur Highway.
Persily said the only work the LNG project has planned for the winter in Nikiski is to demolish some buildings — he estimated about 10 — on recently bought property.
“They’ve shut down their field work, and they’ll be back next summer to do more hole-drilling or water-well testing,” Persily said.
He said the project’s summer 2016 fieldwork will be planned in a meeting on Dec. 4. Possible work may include digging a test trench in the Inlet floor in front of the export terminal site, in order to observe how quickly the dredged Inlet bottom fills back in.
As for the Kenai Spur Highway relocation project — in which the AK LNG Project will plan, permit, and construct a new segment of the highway that would swerve around the future export terminal and give the road to the Alaska Department of Transportation afterward — Persily said “their plan is to spend pretty much all of 2016 planning.”
In summer 2017, Persily said that the project will decide on a preferred route for the new road. Persily distributed copies of a borough-created map showing the projected terminal site and 12 possible routes the relocated Spur Highway may take around it, a tangle of possibilities he jokingly called the “spaghetti bowl.”
Persily estimated that to move the road and build the terminal, the LNG project will need to buy about 600 properties in the area. He emphasized that AK LNG does not have a power of eminent domain — the power to force landowners to sell their property — and said the variety of potential routes allows the project to operate flexibly without it.
“They need to pick a preferred route,” Persily said. “If they can’t buy the land, then it isn’t going to be their preferred route anymore.”
In order to get eminent domain, AK LNG would have to be granted the power by the state Legislature.
Both Persily and Navarre said the LNG pipeline and the Spur Highway relocation were separate projects, although both are being carried out by the same organization for the same ultimate goal. Persily said there was a possible, though unlikely, scenario in which the highway would be relocated even if the export terminal and pipeline are never built.
The export terminal is scheduled to begin construction in 2019, with the relocated highway already planned to be in place by the end of 2018. If AK LNG decides to cancel the pipeline project between the two construction periods, the Nikiski area could be left with a new highway and no plant or terminal.
“Maybe in 2019, if they don’t get their final permit, or there’s a lawsuit, or the market’s crappier than it is now, they could decide ‘we’re not going to build the plant this year,’” he said. “But we’ve already got the highway. So we may end up with a relocated highway regardless of whether the LNG plant goes in. But given how much it’s going to cost them to build the highway, before they start the construction I bet you they’ll be pretty sure they’re going to go ahead with the LNG plant.”
Navarre, a member of the Municipal Advisory Gas Project Review Board created to advise the Legislature on local effects of gasline projects, spoke to the attendees about one of that group’s activities.
Navarre said that the Municipal Advisory Board was currently negotiating for $800 million in local impact aid money during the project’s five-year construction — equaling $160 million each year — to be given to local governments to pay for new costs brought on by construction activity and the large number of people it will bring to the area. Navarre gave examples of needs that could be funded with the impact aid money: hiring new teachers for an increased number of students in local schools, or hiring new emergency response personnel.
Navarre said the local impact aid money would not fund impacts of the highway relocation. Ultimately, he said, the money would be distributed by the Legislature with advice from the Municipal Advisory Board.
Nikiski resident Heidi Hatch asked what would happen to the local impact aid money on the borough level.
“What safeguards will be in place that the borough doesn’t just disperse this money to other communities that aren’t impacted like Nikiski?” Hatch asked. “How will we be sure Nikiski is getting that?”
“Not everybody who works on this project or is part of this project is going to live in Nikiski,” Navarre said. “But Nikiski is going to have a big part of this aid. But for example the airport in Kenai may need something done for the different flights and activities that are going on. ... So I can’t say with any certainty how the money will be dispersed.”
Persily gave another caveat.
“The impact aid is not like punitive damages in court, where you get $1,000 to pay your medical bills and you get $100,000 for pain and suffering. The impact aid, as it’s intended, is to cover direct costs of the project. Expanding the parking lot or terminal at the Kenai airport, or roads in Nikiski, or adding another firetruck and six more full-time staffers and an ambulance. That’s what the impact aid is going to be.”
Many questions received only speculative answers, such as the logistics of the 5,000-person man-camp to be built for workers during the terminal’s construction and the long-term future of the global LNG market. The most consistent message Persily and Navarre gave was that the project is still full of unknowns.
“There are a lot of unknowns at this point,” Navarre said. “There is not even certainty that the project is going to go forward.”
Persily said the next opportunity for public input on the AK LNG project will come after public comment period on the Federal Energy Regulatory Commission’s environmental permitting process ends on Dec. 4.
Reach Ben Boettger at [email protected]

KENAI — Although few specifics of the Alaska Liquid Natural Gas Project’s contracting procedures have been worked out, Alaska LNG contracting engineer Dan DeVries felt confident telling a diverse gathering of Kenai Peninsula contractors, service-providers, and business owners that “for this project, we (Alaska LNG) will need basically everything.”
On April 29, DeVries spoke to approximately 146 registered guests at the Cannery Lodge in Kenai during the Alaska LNG Project’s information session for businesses interested in working on the project of building more than 800 miles of pipeline from northern Alaska gas fields to a liquefaction and storage facility to be constructed in Nikiski.
External affairs manager Kim Fox said that the number of contracted jobs Alaska LNG Project, or AK LNG, might seek and its budget for those jobs were “impossible to say right now” because neither the contracting strategy nor the exact engineering of the estimated $45-$65 billion project have been determined.
However, AK LNG was able to present attendees with a long list of general needs, including construction and administrative services, environmental consultation, material supply, aviation, land, and marine transport, medical services, snow removal, pest control, and cleaning, catering, garbage disposal, and maintenance services for the work camps the project is anticipated to require.
During his presentation, DeVries said that the majority of the work will be subcontracted by competitive bidding through a group of prime contractors who have yet to be hired.
He said AK LNG will prioritize local hiring because local businesses have experience working under Alaska environmental conditions, and that contractors and subcontractors will be held to environmental, safety, quality, and cost standards that have not yet been finalized.
Many of the project’s contracting decisions will be made following a logistics study by PRL Logistics, which was represented at the information session by its external affairs director Dianne Blumer and by president and Cannery Lodge owner Ron Hyde.
Hyde said that the local logistical needs of the Alaska LNG project will go beyond the construction of the pipeline and liquefaction plant.
“The project is currently developing their estimate of demand,” Hyde said. “And what we’re finding is that tremendous infrastructure will have to be built.
Additional roads, additional improvements to port facilities, tons of man-camp type locations. The socioeconomic impact to the workforce is going to be massive... for transportation and logistics, there’s going to be huge, huge opportunities.”
Although speakers at the session emphasized the importance of hiring local businesses, many expect the massive demands of the project to exceed locally available labor supply. Rebecca Logan, general manager of the state-wide trade association Alaska Support Industry Alliance, said that although outside workers will likely be brought in, doing so would not necessarily displace qualified Alaskan workers.
“Every Alaskan who wants to work on this project who is capable will have the opportunity,” Logan said. “It’s going to be one of the largest projects not only in Alaska, but in North America. And when you talk about the workforce we have ... we will never be able to meet the complete need. But our goal is to help every Alaskan company and worker who wants to work on that project be able to work on that project.”
Logan estimated that the majority of conference attendees were Alliance members. She said that although the Alliance will not participate directly in the contracting process, preparing for the possibility of LNG contracts could become a focus of its educational sessions for members.
“I could envision us getting us into some technical training to help some of these small contractors prepare for that,” Logan said. “Maybe looking at some of the bigger LNG projects in the U.S. that have been completed, and what those areas have done to help their smaller local contacts participate.”
At least one representative of local government also attended the session. Larry Persily, an assistant to Kenai Borough Mayor Mike Navarre hired to serve as the Borough’s liaison with the LNG project, said that although none of the information presented was new to him, he attended in order “to get a sense of the questions from the community.”
Persily, who also attended a previous information session in Anchorage, said that ensuring local hiring was a concern he had heard voiced in both places. When asked if the Kenai Peninsula Borough is able to do anything to encourage local hire, Persily said “We’ll keep reminding them so they don’t forget.”
“Certainly Alaska’s not going to be able to fill every job on this project,” Persily said. “So it’s a matter of working on job training so you fill as many as possible, but also accepting that some are not going to be filled with Alaskans, and there the borough wants to make sure that if they have to bring in temporary workers the impact on services is manageable. If you talk about work camps, and highway traffic, it’s going to be more of an impact if you have to bring in a lot of workers than if you use people who live here. So we’ll be tracking all of them and sticking our nose in as best we can.”
Although the contracting process has yet to begin, interested businesses are presently able to add their names to a list on Alaska LNG’s website. Fox said that prior to the information sessions, which in addition to the April 29 meeting in Kenai include previous meetings in Anchorage and Fairbanks and a May 1 presentation in Barrow, approximately 150 businesses had done so.
Ben Boettger can be reached at [email protected]

KENAI — Following the start of Alaska’s official fire season on April 1, outdoor fire-starters will need permission to burn from state authorities. Burn permits, issued by the state Division of Forestry and valid for one year, are now required.
Permit holders will be allowed to light piles of debris up to four feet high and 10 feet in diameter, as well as one-acre fields with grass up to four inches high, on days when burning is allowed.
Burning larger piles or fields will require an inspection from Forestry Staff.
The free permits can be applied for online or in-person at a Division of Forestry office. In addition to the state permits, Kenai, Homer, Seward, and Kodiak require municipal burn permits for fires within city limits, which can be applied for at local fire stations.
Although the state permit is necessary only in summer, Kenai’s burn permit is required year-round.
The permits require holders to call a Division of Forestry information hotline or visit the Division’s website before burning in order to verify that the day is open for burning. Kenai permits also require holders to notify the Kenai fire department prior to a burn.
According to a press release from the Department of Forestry, 343 of the 393 wildfires reported in Alaska in 2014 were human-caused, including the Funny River fire that consumed approximately 200,000 acres of forest on the Kenai Peninsula. Kenai Fire Chief Jeff Tucker said that the permits make fire-users more conscious of their responsibilities.
“It’s more a proactive thing,” Tucker said. “It’s not a manner of penalizing folks, but a manner of making them aware.”
Campfires for cooking and warming do not require a burn permit. Neither do trash fires contained in barrels following the state’s approved design — covered with a metal screen and located on a 10-foot-diameter circle of cleared ground.
Burn permits will be required until August 31, although the fire season — and the permit requirement — may be extended through September if conditions are dry.

KENAI — The City of Kenai’s plans for a road providing access to the southern bank of the mouth of the Kenai River are currently being permitted by the Army Corps of Engineers.
The 1,500-foot gravel road would lead from Bowpicker Lane through a city-owned wetland to the beach. Beach-front property owner Jason Yeoman said that the road is one solution to a problem he and his neighbors have experienced during Kenai’s personal use fishery in July.
“Almost every single person that went to the mouth of the river had to go through my property last year,” said Yeoman, whose home lies between the southern river mouth and the closest current access point at the end of Dunes Road. “If they want to get to the mouth of the river, they have to basically trespass private property.”
The proposed road would curve around Yeoman’s property and others in the area.
In addition to trespassing, the present route to the river mouth requires dipnetters to travel through tidal areas where vehicles can become stuck in soft sand and clay. According to Kenai’s permit application, the access road will provide safe access not only to dipnetters, but to maintenance, sanitation, and emergency vehicles that will service them.
An alternative plan avoids impact to the undeveloped wetland by routing the road around its border, through land that is currently in private ownership. The permit says that the City of Kenai has unsuccessfully tried to purchase this property.
The permit notice lists two measures that Kenai may take to mitigate environmental impact to the wetland surrounding the route of the currently proposed road: decreasing the roadbed area by lessening the extension of its sloped shoulders, and to compensate for the loss of habitat with a conservation easement preserving a 3.2-acre wetland area near Sea Catch Drive.
In order to serve the road’s expected dipnetting users, the construction will include electrical and data lines beneath the roadbed leading to a pair of fee stations by the beach entrance.
Yeoman said that nearby property owners hope the road will lessen the nuisance created by the large number of dipnetters traveling to the river mouth, which he said caused stress to his family and damage to his property.
“They’d be going up and down all night,” Yeoman said. “And there’s no noise buffer between our house and the beach, and so they’d keep the children up all night. Bonfires would be near the house. They’d be partying all night. Literally, there was one day that we had a band out there, with an amplifier, a lead singer, and drums.”
Yeoman said that litter was another problem arising from the lack of beach access.
“I’ve got many photos of feces on my property,” Yeoman said. “Because it’s a long way to go down the beach, so they’d just run up in my trees, or right by my house and just go to the bathroom there. Toilet paper everywhere. Broken bottles everywhere on my property.”
Ben Boettger can be reached at [email protected]